Integrated Modeling of Natural Gas & Power

Natural gas (NG) and electric power markets are becoming increasingly intertwined. The clean burning nature of NG, not to mention its low cost due to increases in discovery and extraction technologies over the past several years, has made it a very popular fuel for the generation of electricity. As a result, the power sector is consistently the largest NG consumer. For example, in 2014, 30.5% of the total NG consumption in the United States was used for the generation of electricity (Figure 1).


Figure 1: U.S. Natural Gas Consumption by Sector, 2014. Source

According to EIA’s Annual Energy Outlook (AEO) 2015 projections,

“…natural gas fuels more than 60% of the new generation needed from 2025 to 2040, and growth in generation from renewable energy supplies most of the remainder. Generation from coal and nuclear energy remains fairly flat, as high utilization rates at existing units and high capital costs and long lead times for new units mitigate growth in nuclear and coal-fired generation.”

Economic, environmental and technological changes have helped NG begin to displace coal from its dominant position in power production. Although it was just for a single month, NG surpassed coal for the first time as the most used fuel for electricity generation in April 2015. The EIA also notes that considerable variation in the fuel mix can occur when fuel prices or economic conditions differ from those in the AEO 2015 reference case. The AEO reference case assumes adoption of the Environmental Protection Agency’s (EPA) implementation of Mercury and Air Toxics Standard (MATS) in 2016, but not the Clean Power Plan (CPP). Adoption of CPP, along with favorable market forces, could change the projections of the AEO 2015 reference case significantly. There is a consensus within both NG and power industry that NG-fired power generation will likely increase with the adoption of CPP.

Quantifying such a trend is non-trivial, but is crucial for stakeholders and regulators in both gas and power markets to fully understand what the future holds. Proper accounting of the interdependencies between NG and power markets is integral to the quality of any long-term predictions. Approaches for modelling an integrated NG-power capacity expansion that account for economics and market operations is the key to the most effective analysis.

The issue of gas-power integration has been a topic of active interest in the industry, and that interest is increasing. For example, the East Interconnect Planning Collaborative coordinated a major study in 2013 – 2014 to evaluate the capability of NG infrastructure to: satisfy the needs of electric generation, identify contingencies that could impact reliability in both directions and review dual-fuel capability. Likewise, the notorious “polar vortex” during the winter of 2013-2014 caused unusually cold weather in the New England region, which “tested the ability of gas-fired generators to access fuel supplies,” and caused ISO-NE and others to acknowledge the need to further investigate the issues affecting synchronization between gas and electric systems. More recently, companies like PIRA Energy are sharpening their focus on the interdependencies between gas and electric power.

There is a need for new and improved modeling approaches that realistically consider this growing gas-power market integration. An even greater need is to integrate the modeling of these markets in a way that is both efficient and practical for the end user, and still able to produce commercially viable results. EPIS has extensively tested interfacing AURORAxmp with GPCM, a calibrated NG model developed by RBAC, Inc. Several organizations and agencies have found this approach successful. Utilizing the two models allows us to develop projections for endogenously derived capacity additions (in both electric generation expansion and gas-pipeline expansion), electricity pricing, gas usage and pricing, etc. which are consistent between the two markets. This consistency leads to greater insight and confidence to aid decision-makers.

Figure 2: Abstract representation of integrated NG-power modeling using AURORAxmp and GPCM..

Although the industry is now anxiously waiting for the judiciary to weigh in on the legality of CPP regulations, there is a consensus that some form of carbon emission regulation will likely be in effect in the near future. Some states, such as Colorado, have already undertaken several regulatory initiatives and may implement a state-level CPP-like emissions regulation even if the federal plan is vacated by the courts.

As part of our ongoing research on the topic of gas-power modeling, we have designed and executed a series of test scenarios comparing the standard calibrated cases of AURORAxmp and GPCM against a potential implementation of CPP. If the proposed form of CPP is upheld in the courts, states have a number of implementation options. At this early stage, there has been no good evidence to indicate that one option would be more popular over another. This necessitated we make some broad assumptions in our experimental gas-power integration process. In our test scenarios, we assumed that all states would adopt the mass-based goal with new resource complement option.

An integrated gas-power framework allows us to better understand the most probable direction for the two markets. Our integrated GPCM-AURORAxmp CPP test scenario for the Eastern Interconnect took 7 iterations to converge to a common solution that satisfied both markets. By comparing resulting capacity expansions, fuel share changes, and gas prices between the starting point (Iteration 0) and ending point (Iteration 6) we get a sense of how the markets will coevolve.

Starting capacity expansion in the Eastern Interconnect for GPCM-AURORAxmp model.

Figure 3: Starting capacity expansion in the Eastern Interconnect for GPCM-AURORAxmp model.

Figure 3 shows the capacity expansion resulting from Iteration 0, the starting point of the integrated iterations. Iteration 0 is essentially a standalone power model with no regard for the impact the capacity expansion would have on the gas market. Figure 4 shows the capacity expansion after Iteration 6.

Resulting capacity expansion in the Eastern Interconnect for GPCM-AURORAxmp model.

Figure 4: Resulting capacity expansion in the Eastern Interconnect for GPCM-AURORAxmp model.

The convergent prices of NG were lower for Iteration 6 than Iteration 0 at all major gas hubs. Figure 5 shows the monthly prices at Henry Hub for both the iterations. The lower gas prices are unintuitive, but plausible. The combined gas-power sector has several market forces that are interdependent. We are currently working with gas experts to understand some of the mechanisms that could lead to lower gas prices. We hypothesize that our accounting for capacity expansion in both the markets is one of the drivers for this behaviors and our findings will be reported in a future publication.

Comparison of starting and ending price trajectories with integrated GPCM-AURORAxmp model.

Figure 5: Comparison of starting and ending price trajectories with integrated GPCM-AURORAxmp model.

The lower gas prices highlight one of the key benefits of integrated gas-power models. Standalone modeling frameworks are likely to misrepresent the impact of the complex cross-market mechanisms. Integrated models avoid this particular pitfall by explicitly modeling each market and is a more apt tool for evaluating policies such the CPP. AURORAxmp provides the capability to model any of the implementation plans that states might adopt in the future – rate-based, mass-based, emission trading schemes and so forth. The ability to interface with widely used NG models, such as GPCM, provides a convenient option for analysts to confidently navigate the highly uncertain future of intertwined NG and power markets.

Filed under: Clean Power Plan, Natural GasTagged with: , , ,

Simple-Cycle Combustion Turbines in the CPP

The Environmental Protection Agency’s (EPA) Clean Power Plan (CPP) is full of interesting caveats and exceptions on many issues. One notable quirk is the exclusion of simple-cycle combustion turbines (SCCT) from the list of affected electricity generating units. States must detail how they intend to limit carbon emissions from combined-cycle combustion turbines (CCCT) and coal-powered steam generators, but carbon from SCCTs is not regulated under the CPP.

The EPA’s rationale is that SCCTs cannot meaningfully contribute to emission reductions because they run so rarely. In the full report, the EPA states that it does not expect this to change:

“In addition, while approximately one-fifth of overall fossil fuel-fired capacity (GW) consists of simple cycle turbines, these units historically have operated at capacity factors of less than 5 percent and only provide about 1 percent of the fossil fuel-fired generation (GWh)…the EPA expects existing simple cycle turbines to continue to operate as they historically have operated, as peaking units.”

Is this a realistic assumption? Simple-cycle units currently have low capacity factors, but that is mostly because they are relatively expensive to operate. Natural gas has historically been more expensive than coal. Among units burning natural gas, combined-cycle units are more efficient than simple-cycle units. As such, simple-cycle units are generally kept offline due to their higher operating costs. However, this is not a rule, it is a relationship. If you add costs to one set of generators and not another, the relationship may change.

To illustrate this point, let’s consider a few hypothetical units, operating in 2025, and see how they may respond to carbon pricing. One is a relatively modern and efficient simple-cycle gas plant, another is a typical combined-cycle gas plant, and the last is an older coal plant. Unit characteristics vary significantly within each of these technologies, but we will take a highly competitive simple-cycle and compare it to some of the least competitive coal generation to see where simple-cycle units may start to become cheaper than coal.

Operating characteristics for hypothetical units (2025)

Technology Heat Rate
CO2 Emission Rate
Fuel Cost
Operating Cost
Efficient SCCT 10,000 8.00 18.50 80.00
Typical CCCT 7,500 118 7.00 6.50 52.50
Older Coal ST 12,000 210 3.50 8.50 42.00

We exclude an emission rate for our simple-cycle unit, because they are not regulated under the CPP and will not experience an increase in operating costs due to carbon restrictions or pricing. If we add a carbon price ($/ton) to each of these units, their operating costs will shift accordingly.

Hypothetical Operating Costs by Source and Carbon Price

As the price of carbon reaches $10/ton, the coal unit starts to become more expensive to operate (per MWh of generation) than the combined-cycle unit (Point A). This is expected and intended by the CPP. One of the fundamental building blocks of emission reductions is a shift of generation from coal to combined-cycle units. However, by the time we reach a carbon price of around $30/ton, coal units also become more expensive to operate than simple-cycle generators! Because the SCCT unit is not subject to carbon regulations under the CPP, its costs remain constant, while the operating cost of the coal plant rise quickly as carbon pricing increases.

A carbon price of $30/ton would be unprecedented in the U.S., but not inconceivable. Depending on which discount rate you prefer, the official social cost of carbon can exceed $30/ton. At EPIS, our modeling of mass-based compliance approaches to the CPP have shown that allowance prices greater than $30/ton may be needed for some states to meet their emission goals through a carbon market.

Of course, unit operation cannot be summed up by a single operating cost. Many factors can influence a generator’s decision to run, such as start costs, other environmental regulations, and participation in reserve or ancillary service markets. There may be reasons beyond per-MWh costs why an SCCT unit would continue to provide only peaking services in a high carbon price environment. However, some power providers may find that the strict emission limits placed on coal and combined-cycle plants opens up a unique opportunity for the relatively unregulated SCCT units. Anyone concerned with modeling the CPP would do well to carefully consider the potentially changing role of SCCTs in an uneven regulatory environment, which gives them a free pass while hindering coal and combined-cycle plants.

Will simple-cycle units increase their utilization if the CPP is implemented, becoming more than just peak power providers? Only time will tell. Let us know what you think in the comments.

Filed under: Clean Power Plan, Power Market InsightsTagged with: , , , , , , , ,